Method for recovering viscous petroleum

Abstract

Steam flooding is frequently unsuccessful in viscous petroleum-containing formations such as tar sand deposits due to loss of steam transmissibility caused by the steam condensing deep in the formation and also caused by heated viscous petroleum forming an oil bank and losing heat and becoming more viscous as it moves through the formation, eventually becoming essentially immobile and blocking further flow through the formation. By injecting a non-condensible, non-oxidizing gas ahead of and/or in combination with steam, this tendency to block or plug the flow channels is reduced or eliminated. Steam and non-condensible, non-oxidizing gas are injected into the formation at a pressure in pounds per square inch not exceeding numerically the overburden thickness in feet in order to avoid fracturing the overburden. Steam and non-condensible, non-oxidizing gas may be mixed prior to injection or injected sequentially or simultaneously to mix in the formation. If steam and non-condensable, non-oxidizing gas are injected separately and simultaneously or sequentially, it is preferred that the gas be injected at a point below where the steam is injected. Steam and gas should be injected so substantially all of the formation to be contacted by injected fluid is contacted by a mixture of steam and the non-condensible, non-oxidizing gas. Suitable non-condensible, non-oxidizing gases include nitrogen, carbon dioxide, flue gas, exhaust gas, natural gas, liquefied petroleum gas, methane, ethane, propane, butane, pentane, hydrogen, and mixtures thereof. Saturated or supersaturated steam may be used.

I claim: 
     
       1. A method of recovering viscous petroleum including bitumen from a subterranean, viscous petroleum-containing formation including a tar sand deposit, said formation being penetrated by at least one injection well and by at least one production well, said injection well containing at least two separate flow paths, the first being in fluid communication with the upper portion of the petroleum formation and the second being in fluid communication with the lower portion of the formation, comprising: (a) injecting steam into the upper portion of the formation via the first flow path; and   (b) injecting a gas which is non-condensable and non-oxidizing at formation conditions into the lower portion of the petroleum containing formation via the second flow path, said non-condensable gas being selected from the group consisting of nitrogen, methane, ethane, propane, butane, natural gas, liquefied petroleum gas, ethylene, propylene, butylene, hydrogen, and mixtures thereof, said non-condensable gas being injected essentially simultaneously with steam injection so the steam and non-condensable gas mix in the formation and the non-condensable gas contacts substantially all of the viscous petroleum contacted by the steam, thereby preventing loss of steam transmissibility in the formation due to steam condensation or creation of an immobile viscous oil bank in the formation, said steam and gas displacing petroleum toward the production well; and   (c) recovering petroleum from the formation via the production well.   
     
     
       2. A method as recited in claim 1 comprising the additional step of injecting sufficient non-condensable, non-oxidizing gas into the formation prior to injecting steam thereinto, said gas being injected into both the upper and lower portion of the formation via both flow paths so as to contact at least ten percent of the pore volume of the formation to be contacted by steam. 
     
     
       3. A method as recited in claim 2 wherein non-condensable, non-oxidizing gas injection is continued until production thereof occurs at the production well before steam injection is initiated. 
     
     
       4. A method as recited in claim 1 wherein the pressure expressed in pounds per square inch at which the steam is injected into the formation is not greater numerically than the thickness of the overburden expressed in feet. 
     
     
       5. A method as recited in claim 1 wherein the pressure expressed in pounds per square inch at which the non-condensable, non-oxidizing gas is injected into the formation is not greater numerically than the thickness of the overburden expressed in feet. 
     
     
       6. A method as recited in claim 1 wherein the non-condensable, non-oxidizing gas is nitrogen. 
     
     
       7. A method as recited in claim 1 wherein the non-condensable, non-oxidizing gas is methane. 
     
     
       8. A method as recited in claim 1 wherein the non-condensable, non-oxidizing gas is ethane. 
     
     
       9. A method as recited in claim 1 wherein the non-condensable, non-oxidizing gas is propane. 
     
     
       10. A method as recited in claim 1 wherein the non-condensable, non-oxidizing gas is butane. 
     
     
       11. A method as recited in claim 1 wherein the non-condensable, non-oxidizing gas is hydrogen. 
     
     
       12. A method as recited in claim 1 wherein the ratio of the non-condensable, non-oxidizing gas to the steam is from about 0.10 to about 10 standard cubic feet of gas per pound of steam. 
     
     
       13. A method as recited in claim 1 wherein the ratio of the flow rate of non-condensable, non-oxidizing gas to the flow rate of steam is decreased with time. 
     
     
       14. A method as recited in claim 1 wherein non-condensable, non-oxidizing gas is injected after steam injection is terminated. 
     
     
       15. A method as recited in claim 1 wherein water is injected after termination of steam injection.